Fuel combusting method

ABSTRACT

The present techniques are directed to systems and a method for combusting a fuel in a gas turbine. An exemplary method includes providing a fuel to a combustor on a gas turbine, providing an oxidant to the combustor, and combusting the fuel and the oxidant in the combustor to produce an exhaust gas. At least a portion of the exhaust gas is passed through a water-gas shifting catalyst to form a low CO content product gas.

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims the priority benefit of U.S. Patent Application61/767,688 filed Feb. 21, 2013 entitled FUEL COMBUSTING METHOD, theentirety of which is incorporated by reference herein.

FIELD OF THE INVENTION

The present disclosure relates generally to low-emission powergeneration systems. More particularly, the present disclosure relates tosystems and methods for changing the composition of components inexhaust gases from gas turbine systems.

BACKGROUND

This section is intended to introduce various aspects of the art, whichmay be associated with exemplary embodiments of the present techniques.This discussion is believed to assist in providing a framework tofacilitate a better understanding of particular aspects of the presenttechniques. Accordingly, it should be understood that this sectionshould be read in this light, and not necessarily as admissions of priorart.

The combustion of fuel within a combustor, e.g., integrated with a gasturbine, can be controlled by monitoring the temperature of the exhaustgas. Under full load conditions, typical gas turbines adjust the amountof fuel introduced to a number of combustors in order to reach a desiredcombustion gas or exhaust gas temperature. Conventional combustionturbines control the oxidant introduced to the combustors using inletguide vanes. Under partial load conditions, the amount of oxidantintroduced to the combustor is reduced and the amount of fuel introducedis again controlled to reach the desired exhaust gas temperature.Further, at partial load, the efficiency of gas turbines drops becausethe ability to reduce the amount of oxidant is limited by the inletguide vanes, which are only capable of slightly reducing the flow ofoxidant. Further, the oxidant remains at a constant lower flow rate whenthe inlet guide vanes are in their flow restricting position. Theefficiency of the gas turbine then drops when it is at lower powerproduction because to make that amount of power with that mass flow alower expander inlet temperature is required. Moreover, existing oxidantinlet control devices may not allow fine flow rate control and mayintroduce large pressure drops with any restriction on the oxidant flow.With either of these approaches to oxidant control, there are potentialproblems with lean blow out at partial load or reduced pressureoperations.

Controlling the amount of oxidant introduced to the combustor can bedesirable when an objective is to capture carbon dioxide (CO₂) from theexhaust gas. Current carbon dioxide capture technology is expensive dueto several reasons. One reason is the low pressure and low concentrationof carbon dioxide in the exhaust gas. The carbon dioxide concentration,however, can be significantly increased from about 4% to greater than10% by operating the combustion process under substantiallystoichiometric conditions. Further, a portion of the exhaust gas may berecycled to the combustor as a diluent in order to control thetemperature of the gas within the combustor and of the exhaust gas.Also, any unused oxygen in the exhaust gas may be a contaminate in thecaptured carbon dioxide, restricting the type of solvents that can beutilized for the capture of carbon dioxide.

In many systems, an oxidant flow rate may be reduced by altering theoperation of a separate oxidant system. For example, an independentoxidant compressor may be throttled back to a slower operating speedthereby providing a decreased oxidant flow rate. However, the reductionin compressor operating speed generally decreases the efficiency of thecompressor. Additionally, throttling the compressor may reduce thepressure of the oxidant entering the combustor. In contrast, if theoxidant is provided by the compressor section of the gas turbine,reducing the speed is not a variable that is controllable during powergeneration. Large gas turbines that are used to produce 60 cycle powerare generally run at 3600 rpm. Similarly, to produce 50 cycle power thegas turbine is often run at 3000 rpm. In conventional gas turbinecombustor operations the flow of oxidant into the combustor may notwarrant significant control because the excess oxidant is used ascoolant in the combustion chamber to control the combustion conditionsand the temperature of the exhaust gas. A number of studies have beenperformed to determine techniques for controlling combustion processesin gas turbines.

International Patent Application Publication No. WO/2010/044958 byMittricker et al. discloses methods and systems for controlling theproducts of combustion, for example, in a gas turbine system. Oneembodiment includes a combustion control system having an oxygenationstream substantially comprising oxygen and CO₂ and having an oxygen toCO₂ ratio, then mixing the oxygenation stream with a combustion fuelstream and combusting in a combustor to generate a combustion productsstream having a temperature and a composition detected by a temperaturesensor and an oxygen analyzer, respectively. The data from the sensorsare used to control the flow and composition of the oxygenation andcombustion fuel streams. The system may also include a gas turbine withan expander and having a load and a load controller in a feedbackarrangement.

International Patent Application Publication No. WO/2009/120779 byMittricker et al. discloses systems and methods for low emission powergeneration and hydrocarbon recovery. One system includes integratedpressure maintenance and miscible flood systems with low emission powergeneration. Another system provides for low emission power generation,carbon sequestration, enhanced oil recovery (EOR), or carbon dioxidesales using a hot gas expander and external combustor. Another systemprovides for low emission power generation using a gas power turbine tocompress air in the inlet compressor and generate power using hot carbondioxide laden gas in the expander.

U.S. Pat. No. 4,858,428 to Paul discloses an advanced integratedpropulsion system with total optimized cycle for gas turbine. Pauldiscloses a gas turbine system with integrated high and low pressurecircuits having a power transmission for extracting work from one of thecircuits, the volume of air and fuel to the respective circuits beingvaried according to the power demand monitored by a microprocessor. Theturbine system has a low pressure compressor and a staged high pressurecompressor with a combustion chamber and high pressure turbineassociated with the high pressure compressor. A combustion chamber and alow pressure turbine are associated with the low pressure compressor,the low pressure turbine being staged with the high pressure turbine toadditionally receive gases expended from the high pressure turbine and amicroprocessor to regulate air and gas flows between the compressor andturbine components in the turbine system.

U.S. Pat. No. 4,271,664 to Earnest discloses a turbine engine withexhaust gas recirculation. The engine has a main power turbine operatingon an open-loop Brayton cycle. The air supply to the main power turbineis furnished by a compressor independently driven by the turbine of aclosed-loop Rankine cycle which derives heat energy from the exhaust ofthe Brayton turbine. A portion of the exhaust gas is recirculated intothe compressor inlet during part-load operation.

U.S. Patent Application Publication No. 2009/0064653 by Hagen et al.discloses partial load combustion cycles. The part load method controlsdelivery of diluent fluid, fuel fluid, and oxidant fluid inthermodynamic cycles using diluent to increase the turbine inlettemperature and thermal efficiency in part load operation above thatobtained by relevant art part load operation of Brayton cycles, foggedBrayton cycles, or cycles operating with some steam delivery, or withmaximum steam delivery.

U.S. Pat. No. 5,355,668 to Weil et al. discloses a catalyst-bearingcomponent of a gas turbine engine. Catalytic materials are formed oncomponents in the gas flow path of the engine, reducing emissions ofcarbon monoxide and unburned hydrocarbons. The catalytic materials areselected from the noble metals and transition metal oxides. The portionsof the gas flow path where such materials are applied can include thecombustor, the turbine, and the exhaust system. The catalytic coatingcan be applied in conjunction with a thermal barrier coating systeminterposed between a substrate component and the catalytic coating.

While some past efforts to control the oxidant flow rate haveimplemented oxidant inlet control devices, such systems disclosed acontrol of all of the combustors together, failing to account fordifferences between combustors. Further, the systems were limited intheir ability to finely tune the oxidant flow rate. As a result, theconcentration of certain gases in the exhaust was higher than desirable.

SUMMARY

An exemplary embodiment of the present techniques provides a method forcombusting a fuel in a gas turbine. The method includes providing a fuelto a combustor on a gas turbine, providing an oxidant to the combustor,and combusting the fuel and the oxidant in the combustor to produce anexhaust gas. At least a portion of the exhaust gas is passed through awater-gas shifting catalyst to form a low CO content product gas.

Another embodiment provides a gas turbine system. The gas turbine systemincludes an oxidant system, a fuel system, and a control system. Acombustor is adapted to receive and combust an oxidant from the oxidantsystem and a fuel from the fuel system to produce an exhaust gas. Acatalyst unit including a water gas shifting (WGS) catalyst isconfigured to reduce the concentration of carbon monoxide in the exhaustgas to form a low CO content product gas.

Another embodiment provides a heat recovery unit. The heat recovery unitincludes a heat exchanger configured to remove heat energy from anexhaust gas, and a water gas shifting (WGS) catalyst bed configured toreduce a concentration of a target gas in the exhaust gas.

BRIEF DESCRIPTION OF THE DRAWINGS

The advantages of the present techniques are better understood byreferring to the following detailed description and the attacheddrawings, in which:

FIG. 1 is a schematic diagram of a gas turbine system that includes agas turbine;

FIG. 2 is a schematic of a gas turbine system that can be used to adjustthe fuel and the oxidant flow to the combustors of a gas turbine engine;

FIG. 3 is a schematic of a gas turbine system that includes an HRSG onthe exhaust stream from the expander exhaust section;

FIGS. 4A and 4B are graphical depictions of a simulation showing therelationship between the concentration of oxygen and carbon monoxide asthe equivalence ratio (φ) changes from 0.75 to 1.25 and from 0.999 to1.001, respectively;

FIG. 5 is a block diagram of a method for adjusting fuel and oxidantlevels to the combustors based on readings from an array of sensors;

FIG. 6 is a block diagram of a plant control system that may be used tocontrol the oxidant and fuel to the combustors in a gas turbine engine;and

FIG. 7 is a schematic of a simulated gas turbine system that illustratesthe use of two catalyst beds in a heat-recovery steam generator (HRSG)to reduce the concentration of selected components in an exhaust stream.

DETAILED DESCRIPTION

In the following detailed description section, specific embodiments ofthe present techniques are described. However, to the extent that thefollowing description is specific to a particular embodiment or aparticular use of the present techniques, this is intended to be forexemplary purposes only and simply provides a description of theexemplary embodiments. Accordingly, the techniques are not limited tothe specific embodiments described below, but rather, include allalternatives, modifications, and equivalents falling within the truespirit and scope of the appended claims.

At the outset, for ease of reference, certain terms used in thisapplication and their meanings as used in this context are set forth. Tothe extent a term used herein is not defined below, it should be giventhe broadest definition persons in the pertinent art have given thatterm as reflected in at least one printed publication or issued patent.Further, the present techniques are not limited by the usage of theterms shown below, as all equivalents, synonyms, new developments, andterms or techniques that serve the same or a similar purpose areconsidered to be within the scope of the present claims.

A “combined cycle power plant” uses both steam and gas turbines togenerate power. The gas turbine operates in an open or semi-open Braytoncycle, and the steam turbine operates in a Rankine cycle powered by theheat from the gas turbine. These combined cycle gas/steam power plantsgenerally have a higher energy conversion efficiency than gas or steamonly plants. A combined cycle plant's efficiencies can be as high as 50%to 60%. The higher combined cycle efficiencies result from synergisticutilization of a combination of the gas turbine with the steam turbine.Typically, combined cycle power plants utilize heat from the gas turbineexhaust to boil water to generate steam. The boilers in typical combinedcycle plants can be referred to as heat recovery steam generator (HRSG).The steam generated is utilized to power a steam turbine in the combinedcycle plant. The gas turbine and the steam turbine can be utilized toseparately power independent generators, or in the alternative, thesteam turbine can be combined with the gas turbine to jointly drive asingle generator via a common drive shaft.

A diluent is a gas that is primarily used to reduce the combustortemperatures that result from the combustion of a fuel and oxidant. Adiluent may be used to lower the concentration of oxidant or fuel (orboth) that is fed to a gas turbine and/or to dilute the products ofcombustion. The diluent may be an excess of nitrogen, CO₂, combustionexhaust, or any number of other gases. In embodiments, a diluent mayalso provide cooling to a combustor and/or other parts of the gasturbine.

As used herein, a “compressor” includes any type of equipment designedto increase the pressure of a working fluid, and includes any one typeor combination of similar or different types of compression equipment. Acompressor may also include auxiliary equipment associated with thecompressor, such as motors, and drive systems, among others.

The compressor may utilize one or more compression stages, for example,in series. Illustrative compressors may include, but are not limited to,positive displacement types, such as reciprocating and rotarycompressors for example, and dynamic types, such as centrifugal andaxial flow compressors, for example. For example, a compressor may be afirst stage in a gas turbine engine, as discussed in further detailbelow.

A “control system” typically comprises one or more physical systemcomponents employing logic circuits that cooperate to achieve a set ofcommon process results. In an operation of a gas turbine engine, theobjectives can be to achieve a particular exhaust composition andtemperature. The control system can be designed to reliably control thephysical system components in the presence of external disturbances,variations among physical components due to manufacturing tolerances,and changes in inputted set-point values for controlled output values.Control systems usually have at least one measuring device, whichprovides a reading of a process variable, which can be fed to acontroller, which then can provide a control signal to an actuator,which then drives a final control element acting on, for example, anoxidant stream. The control system can be designed to remain stable andavoid oscillations within a range of specific operating conditions. Awell-designed control system can significantly reduce the need for humanintervention, even during upset conditions in an operating process.

An “equivalence ratio” refers to the mass ratio of fuel to oxygenentering a combustor divided by the mass ratio of fuel to oxygen whenthe ratio is stoichiometric. A perfect combustion of fuel and oxygen toform CO₂ and water would have an equivalence ratio of 1. A too leanmixture, e.g., having more oxygen than fuel, would provide anequivalence ratio less than 1, while a too rich mixture, e.g., havingmore fuel than oxygen, would provide an equivalence ratio greater than1.

A “fuel” includes any number of hydrocarbons that may be combusted withan oxidant to power a gas turbine. Such hydrocarbons may include naturalgas, treated natural gas, kerosene, gasoline, or any number of othernatural or synthetic hydrocarbons.

A “gas turbine” engine operates on the Brayton cycle. If the exhaust gasis vented, this is termed an open Brayton cycle, while recycling atleast a portion of the exhaust gas gives a semi-open Brayton cycle. In asemi-open Brayton cycle, at least fuel and oxidant are added to thesystem to support internal combustion and a portion of the products ofcombustion are vented or extracted. In a closed Brayton cycle, all ofthe exhaust is recycled and none is vented or extracted and heat isadded to the system by external combustion or another means. As usedherein, a gas turbine typically includes a compressor section, a numberof combustors, and a turbine expander section. The compressor may beused to compress an oxidant, which is mixed with a fuel and channeled tothe combustors. The mixture of fuel and oxidant is then ignited togenerate hot combustion gases. The combustion gases are channeled to theturbine expander section which extracts energy from the combustion gasesfor powering the compressor, as well as producing useful work to power aload. In embodiments discussed herein, the oxidant may be provided tothe combustors by an external compressor, which may or may not bemechanically linked to the shaft of the gas turbine engine. Further, inembodiments, the compressor section may be used to compress a diluent,such as recycled exhaust gases, which may be fed to the combustors as acoolant.

A “heat recovery steam generator” or HRSG is a heat exchanger or boilerthat recovers heat from a hot gas stream. It produces steam that can beused in a process or used to drive a steam turbine. A common applicationfor an HRSG is in a combined-cycle power plant, where hot exhaust from agas turbine is fed to the HRSG to generate steam which in turn drives asteam turbine. This combination produces electricity more efficientlythan either the gas turbine or steam turbine alone. As used herein, anHRSG may include any number of heat recovery units in addition to, orinstead of, an HRSG by itself.

A “hydrocarbon” is an organic compound that primarily includes theelements hydrogen and carbon, although nitrogen, sulfur, oxygen, metals,or any number of other elements may be present in small amounts. As usedherein, hydrocarbons generally refer to components found in raw naturalgas, such as CH₄, C₂H₂, C₂H₄, C₂H₆, C₃ isomers, C₄ isomers, benzene, andthe like.

An “oxidant” is a gas mixture that can be flowed into the combustors ofa gas turbine engine to combust a fuel. As used herein, the oxidant maybe oxygen mixed with any number of other gases as diluents, includingCO₂, N₂, air, combustion exhaust, and the like.

A “sensor” refers to any device that can detect, determine, monitor,record, or otherwise sense the absolute value of or a change in aphysical quantity. A sensor as described herein can be used to measurephysical quantities including, temperature, pressure, O₂ concentration,CO concentration, CO₂ concentration, flow rate, acoustic data, vibrationdata, chemical concentration, valve positions, or any other physicaldata.

“Pressure” is the force exerted per unit area by the gas on the walls ofthe volume. Pressure can be shown as pounds per square inch (psi).“Atmospheric pressure” refers to the local pressure of the air.“Absolute pressure” (psia) refers to the sum of the atmospheric pressure(14.7 psia at standard conditions) plus the gage pressure (psig). “Gaugepressure” (psig) refers to the pressure measured by a gauge, whichindicates only the pressure exceeding the local atmospheric pressure(i.e., a gauge pressure of 0 psig corresponds to an absolute pressure of14.7 psia). The term “vapor pressure” has the usual thermodynamicmeaning. For a pure component in an enclosed system at a given pressure,the component vapor pressure is essentially equal to the total pressurein the system.

“Substantial” when used in reference to a quantity or amount of amaterial, or a specific characteristic thereof, refers to an amount thatis sufficient to provide an effect that the material or characteristicwas intended to provide. The exact degree of deviation allowable may insome cases depend on the specific context.

Overview

Embodiments of the present invention provide a system and a method forconsuming carbon monoxide generated in the combustion in a gas turbineengine. This is performed by a water gas shift reaction, for example, ina catalyst bed located in a heat-recovery steam generator (HRSG). Thewater gas shift reaction is a chemical reaction between carbon monoxideand water vapor that forms carbon dioxide and hydrogen as products. Thewater-gas shift reaction is a predominant reaction given the relativelylarge quantity of water vapor present in the exhaust from the gasturbine. In some embodiments, such as in a stoichiometric exhaust gasrecirculation (SEGR) gas turbine, the exhaust is a recirculated lowoxygen content gas stream, which is used at least as a coolant gas inthe combustors. Typically, water vapor content of more than 10 volumepercent (>100 k parts per million volume, ppmv) is present in therecirculated low oxygen content gas stream while oxygen, carbon monoxideand hydrogen are of the order of 1000 to 5000 ppmv. As a result, thewater-gas shift reaction is able to consume residual carbon monoxideplus a similar quantity of water vapor to create carbon dioxide andhydrogen at a higher conversion efficiency than the competing oxidationreactions. The resulting low CO content product gas may comprise aslittle as 1 or 2 ppm CO.

A moderate conversion efficiency may be acceptable, since the highconcentration of water vapor relative to the concentration of carbonmonoxide will still tend to force a high conversion. The catalyst bedmay be located in a moderate temperature zone of the HRSG, e.g., in azone of about 150° C. to about 250° C. or 100° C. to 400° C., sincelower temperature zones of the HRSG are well suited for catalyst systemsdesigned for a water-gas shift reaction. Hydrogen formed in the reactionwill likely have a very low conversion efficiency to oxidization towater vapor. Accordingly, the hydrogen may be recirculated within therecirculated low oxygen content gas stream to the compressor section ofthe SEGR gas turbine and then may either be extracted as part of theproduct stream, used as part of the sealing and cooling stream of thegas turbine hot gas path or transit to the combustor where this hydrogenshould be largely oxidized within the combustors. The hydrogen partextracted as part of the product stream should be easily oxidized towater vapor within the first oxidation catalyst unit included within theproduct extraction circuit. Overall, this arrangement should provideimproved conversion efficiency.

In some embodiments described herein, an oxidation catalyst is used in ahot zone of the HRSG to oxidize carbon monoxide, hydrogen, and unburnedhydrocarbons with residual oxygen from the gas turbine exhaust, formingcarbon dioxide and water. A moderate oxidizing conversion efficiency maybe accepted in order to provide a low pressure drop across a catalystbed.

Sensors may be placed in the exhaust gas, the product gas, or both toadjust the combustion conditions to control the amount of CO, oxygen orother contaminants in the exhaust gas. For example, the sensors may belocated in a ring on an expander exhaust, an inlet to the catalyst bed,an outlet from a catalyst bed, or any combination. The sensors mayinclude lambda sensors, oxygen sensors, carbon monoxide sensors, andtemperature sensors, among others. Further, combinations of differenttypes of sensors may be used to provide further information.

In some embodiments, multiple sensors may be used to adjust theconditions in individual combustors on the gas turbine. The sensors maynot have a one-to-one relationship to particular combustors, but may beinfluenced by a particular combustor. The response of various sensorsmay be related back to a particular combustor, for example, using sumand difference algorithms that may be based on swirl charts. Swirlcharts relate patterns of exhaust flow in an expander to combustors thatmay have contributed to the exhaust flow at that point.

The use of individually controlled combustors may increase the burnefficiency of a gas turbine engine, e.g., making the burn closer to aone-to-one equivalence ratio. Such improvements in efficiency may lowerO₂, unburned hydrocarbons, and carbon monoxide in the exhaust. This maymake the use of an oxidation catalyst more problematic, as bothreactants are present in small amounts. However, the large amount ofwater vapor in the exhaust can maintain a high rate of conversion of theCO in the water gas shift reaction.

FIG. 1 is a schematic diagram of a gas turbine system 100 that includesa gas turbine engine 102. The gas turbine engine 102 may have acompressor 104 and a turbine expander 106 on a single shaft 108. The gasturbine engine 102 is not limited to a single shaft arrangement, asmultiple shafts could be used, generally with mechanical linkages ortransmissions between shafts. In various embodiments, the gas turbineengine 102 also has a number of combustors 110 that feed hot exhaust gasto the expander, for example, through lines 112. For example, a gasturbine 102 may have 2, 4, 6, 14, 18, or even more combustors 110,depending on the size of the gas turbine 102.

The combustors 110 are used to burn a fuel provided by a fuel source114. An oxidant may be provided to each of the combustors 110 fromvarious sources. For example, in embodiments, an external oxidant source116, such as an external compressor, may provide the oxidant to thecombustors 110. In embodiments, an oxidant or recycled exhaust gases118, or a mixture thereof, may be compressed in the compressor 104 andthen provided to the combustors 110. In other embodiments, such as whenan external oxidant source 116 is provided, the compressor 104 may beused to compress only the recycled exhaust gas, which may be fed to thecombustors 110 for cooling and dilution of the oxidant.

The exhaust gas from the combustors 110 expands in the turbine expander106, creating mechanical energy. The mechanical energy may power thecompressor 104 through the shaft 108. Further, a portion of themechanical energy may be harvested from the gas turbine as a mechanicalpower output 120, for example, to generate electricity or to poweroxidant compressors. The expanded exhaust gas 122 may be vented, usedfor heat recovery, recycled to the compressor 104, or used in anycombinations thereof. In an embodiment, the exhaust gas 122 is flowedthrough one or more catalyst beds that include a water gas shiftcatalyst, and oxidation catalyst, or both.

In some embodiments, the oxidant is metered to the combustors 110 tocontrol an equivalence ratio of the fuel to the oxidant. The meteringmay be performed for all combustors 110 together, for example, byadjusting the fuel 114 and oxidant 116 sources, or each individualcombustor 110. It will be apparent to one of skill in the art that astoichiometric burn, e.g., at an equivalence ratio of 1, will be hotterthan a non-stoichiometric burn. Therefore, either excess oxidant or anadded non-combustible gas, such as a recycle exhaust gas, can be addedto cool the engine, preventing damage to the combustors 110 or theturbine expander 106 from the extreme heat.

The use of recycled exhaust gas 122 provides a further advantage in thatthe exhaust is deficient in oxygen, making it a better material forenhanced oil recovery. Adjusting individual combustors 110 maycompensate for differences between the combustors 110, improving theoverall efficiency of the gas turbine 102.

Control of Combustors

FIG. 2 is a schematic of a gas turbine system 200 that can be used toadjust the oxidant flow and/or fuel flow to the combustors 110 of a gasturbine engine 102. The referenced units are as generally discussed withrespect to FIG. 1. The system 200 may adjust the amount of oxidant 116provided to the combustors 110, for example, by adjusting the pressure,flow rate, or composition of the oxidant 116. Similarly, the system 200may adjust the amount of fuel 114 provided to the combustors 110 byadjusting the pressure, flow rate, or composition of the fuel 114. In anembodiment, the oxidant flow to each individual combustor 110 may beadjusted by an oxidant flow adjusting device 202, such as a valve,swirler, or mixing section in each combustor 110. An actuator 204 can beused to adjust the oxidant flow adjusting device 202. Similarly, thefuel flow 114 to each individual combustor 110 may be adjusted.

A number of sensors 206 can be placed in an expander exhaust section 208of the gas turbine engine 102, for example, 5, 10, 15, 20, 25, 30 ormore, sensors 206 may be placed in a ring around the expander exhaustsection 208. The number of sensors 206 may be determined by the size ofthe gas turbine 102, the number of combustors 110, or both. The sensors206 may include oxygen sensors, carbon monoxide sensors, temperaturesensors, hydrogen sensors, and the like. Examples of oxygen sensors caninclude lambda and/or wideband zirconia-oxygen sensors, titania sensors,galvanic, infrared, or any combination thereof. Examples of temperaturesensors can include thermocouples, resistive temperature devices,infrared sensors, or any combination thereof. Examples of carbonmonoxide sensors can include oxide based film sensors such as bariumstannate and/or titanium dioxide. For example, a carbon monoxide sensorcan include platinum-activated titanium dioxide, lanthanum stabilizedtitanium dioxide, and the like. The choice of the sensors 206 may becontrolled by the response time, as the measurements are needed for realtime control of the system. The sensors 206 may also includecombinations of different types of sensors 206. The sensors 206 send asignal 210 back to the control system 212, which may be used to makefuel and oxidant adjustment decisions for each, or all, of thecombustors 110. Any number of physical measurements could be performed,for example, the sensors 206 could be used to measure temperature,pressure, CO concentration, O₂ concentration, vibration, and the like.Further, multiple sensors 206 could be used to measure combinations ofthese parameters.

The control system 212 may be part of a larger system, such as adistributed control system (DCS), a programmable logic controller (PLC),a direct digital controller (DDC), or any other appropriate controlsystem. Further, the control system 212 may automatically adjustparameters, or may provide information about the gas turbine 102 to anoperator who manually performs adjustments. The control system 212 isdiscussed further with respect to FIG. 7, below.

It will be understood that the gas turbine system 200 shown in FIG. 2,and similar gas turbine systems depicted in other figures, have beensimplified to assist in explaining various embodiments of the presenttechniques. Accordingly, in embodiments of the present techniques, boththe oxidant system 116 and the fuel system 114, as well as the gasturbine systems themselves, can include numerous devices not shown. Suchdevices can include flow meters, such as orifice flow meters, mass flowmeters, ultrasonic flow meters, venturi flow meters, and the like. Otherdevices can include valves, such as piston motor valves (PMVs) to openand close lines, and motor valves, such as diaphragm motor valves(DMVs), globe valves, and the like, to regulate flow rates. Further,compressors, tanks, heat exchangers, and sensors may be utilized inembodiments in addition to the units shown.

In the embodiment shown in FIG. 2, the compressor 104 may be used tocompress a stream 214, such as a recycled exhaust stream. Aftercompression, the stream 214 may be injected from a line 216 into themixing section of the combustor 110. The stream 214 is not limited to apure recycle stream, as the injected stream 216 may provide the oxidantto the combustor 110. The exhaust stream 218 from the expander exhaustsection 208 may be used to provide the recycle stream, as discussedfurther with respect to FIG. 2, below.

Catalysts and Catalyst Beds

The exhaust stream 218 may be passed through one or more catalyst beds220, for example, attached to the exhaust expander section 208, locatedin an HRSG, or in other places in the gas turbine system 200. Thecatalyst beds 220 may comprise any number of catalyst components. Forexample, a catalyst bed may comprise an oxidation catalyst or a watergas shift catalyst. Multiple catalyst beds may be used in sequence.Generally, an oxidation and/or reduction catalyst bed may be located ina high temperature zone, for example, in an exhaust expander section208, in separate catalyst bed 220 after the exhaust expander 208, or inearly stage of a heat recovery steam generator (HRSG), as discussedherein. A water gas shift catalyst bed may be located in a lowertemperature region of the exhaust flow, such as towards the end of anHRSG. The product gas 222 from the catalyst bed 220 may be a low oxygencontent gas that substantially includes carbon dioxide, nitrogen, argon,hydrogen, and water vapor. Small amounts of carbon monoxide may still bepresent, but may be less than about 5 ppmv, for example, 2 ppmv or 1ppmv.

It can be noted that the catalyst bed 220 is not limited to oxidationcatalysts, but may also include other catalysts that can reduce chemicalcomponents. For example, the catalyst bed 220 may comprise a catalyticconvertor, in which an oxidation catalyst oxidizes CO and unburnedhydrocarbons to CO₂ and H₂O, and a reduction catalyst converts oxides ofnitrogen (NO_(x)) to N₂, CO₂, and H₂O. The oxidation catalyst may be,for example, platinum, palladium, gold, or other metals, supported on arefractory oxide. The refractory oxide may include alumina, silica,titania, zirconia, or mixtures thereof. The reduction catalyst mayinclude, for example, rhodium, or other metals. Additional metals thatmay be used in the catalyst bed 220 include nickel, cerium, iron,manganese, and copper, among others.

The water gas shift (WGS) reaction converts the reagents CO and H₂O toCO₂ and H₂. Any number of WGS catalysts can be used for this reaction,and placed in temperature regions of the HRSG at which the WSG catalystis most active. For example, an iron-chromium oxide catalyst supportedon a refractory oxide, such as alumina, silica, titania, zirconia, ormixtures thereof, may be used in a region that is in a temperature rangeof about 300° C. to about 450° C. Further, a copper-zinc catalystsupport on a refractory oxide may be used in a region that is in atemperature range of about 180° C. to about 270° C. Any number of otherWGS catalysts may be used, including, for example, a platinum-rheniumcatalyst, or catalyst combinations of ruthenium with copper or rhenium.

The refractory oxides supporting the catalytic metal may be held inplace by a honeycombed ceramic structure that is designed to allow flowof the exhaust gas with minimal back pressure. In an HRSG, therefractory oxide holding the catalytic metal may be supported on aceramic that is supported on heat exchanger tubes configured to controlthe reaction temperature.

The sensors 206 are not limited to the expander exhaust section 208, butmay be in any number of other locations, instead of or in addition tothe expander exhaust section 208. For example, the sensors 206 may bedisposed in multiple rings around the expander exhaust section 208.Further, the sensors 206 may be separated into multiple rings by thetype of sensor 206, for example, with oxygen analyzers in one ring andtemperature sensors in another ring. Sensors 224 may also be located inthe product gas stream 222 from the catalyst bed 220.

In embodiments the gas turbine engine 102 may be used to provide power,CO₂, heat energy, or any combinations thereof for numerous applications.For example, the product gas 222 from the catalyst bed 220 may beprocessed in a dehydration unit, such as a cryogenic dehydration system,a glycol system, or a combination system, to form a low dewpoint gas,e.g., with a dewpoint less than about −10° C., less than about −30° C.,less than about −50° C., or lower. Further, the product gas 222 may beprocessed in a carbon dioxide separation unit to produce a lean carbondioxide stream and a rich carbon dioxide stream. The carbon dioxideseparation unit may include solid absorption columns, cryogenicseparation systems, liquid adsorption systems, or chemical sorptionsystems.

Either the lean carbon dioxide stream or the rich carbon dioxide streammay be injected into a subterranean reservoir for enhanced hydrocarbonrecovery. The rich carbon dioxide stream may be injected into a carbonsequestration well, while the lean carbon dioxide stream may be providedas a gaseous product to market. The lean carbon dioxide stream may beprocessed in a dehydration unit to lower the dewpoint prior to sales. Ifsale of the lean carbon dioxide stream is not desirable, the stream maybe passed through an expander to recovery mechanical energy prior toventing the stream.

Energy Recovery and Recycle of Exhaust

FIG. 3 is a schematic of a gas turbine system 300 that includes an HRSG302 on the exhaust stream 218 from the expander exhaust section 208. TheHRSG 302 may include any number of heat recovery units, such as a steamsuperheating device, a steam raising device, a feed water heatingdevice, or an endothermic reaction device, among others. Thus, any HRSG302 referred to herein may be replaced with any other type of heatrecovery unit. Like numbered items are as described above with respectto FIGS. 1 and 2. The exhaust gas in the exhaust stream 218 can include,but is not limited to, unburned fuel, oxygen, carbon monoxide, carbondioxide, hydrogen, nitrogen, nitrogen oxides, argon, water, steam, orany combinations thereof. The exhaust stream 218 can have a temperatureranging from about 430° C. to about 725° C. and a pressure of about 101kPa to about 110 kPa.

In the embodiment shown in the schematic, the heat generated by thecombustion can be used to boil an inlet water stream 304 to generate asteam stream 306 that may also be superheated. The steam stream 306 maybe used, for example, in a Rankine cycle to generate mechanical powerfrom a steam turbine, or to provide steam for utilities, or both. Themechanical power from the steam turbine may be used to generateelectricity, operate compressors, and the like. As noted herein, the gasturbine system 300 is not limited to a HRSG 302, as any type of heatrecovery unit (HRU) may be used. For example, the heat may be recoveredin a heat exchanger to provide hot water or other heated fluids.Further, a Rankine cycle based on an organic working fluid (ORC) may beused to recover heat energy by converting it to mechanical energy.

In an embodiment, one or more catalyst beds 308 may be located in theHRSG 302 and described herein. The catalyst beds 308 may be locatedwithin the HRSG 302 by the reaction temperature desired for thecatalyst. For example, a catalyst that operates at a higher temperature,such as an oxidation catalyst, may be located in the HRSG 302 at a pointjust after the exhaust stream 218 enters the HRSG 302. Similarly, acatalyst that operates at a lower temperature may be located at a laterpoint in the HRSG 302, for example, just before a product gas 310 leavesthe HRSG 302.

The cooled exhaust stream or product gas 310 may then be used for otherpurposes, such as to provide recycle gas for stream 214. Various othersensors may be added to the system to monitor and control the catalyticreaction. For example, sensors 312 may be placed in the product gas 310to determine the efficacy of the catalytic reactions. These sensors 312may be used in addition to the sensors 206 on the expander exhaustsection 208 to determine the reactants present, and to control the fueland oxidant levels.

Individual Control of Equivalence Ratio to Combustors

The gas turbine systems discussed above may be used to control thecombustion process in the combustors 110, either individually, as agroup, or both. A goal of the control may be to balance the equivalenceratio of the fuel and oxygen. This may be performed to minimize unburnedor partially burned hydrocarbon, represented by the CO concentration inan exhaust stream and to minimize unconsumed oxygen in the exhauststream. The equivalence ratio is discussed further with respect to FIG.4A.

FIGS. 4A and 4B are graphical depictions of a simulation showing theequilibrium relationship between the mole fraction 402 of oxygen andcarbon monoxide as the equivalence ratio (φ) 404 changes from 0.75 to1.25 and from 0.999 to 1.001, respectively. The highest efficiency maybe achieved when the equivalence ratio is about 1.0. The oxygenconcentration as a function of the equivalence ratio is shown as line406 and the carbon monoxide concentration as a function of theequivalence ration is shown as line 408. The equivalence ratio (φ) 404is equal to (mol % fuel/mol % oxygen)_(actual)/(mol % fuel/mol %oxygen)_(stoichiometric). The mol % fuel is equal toF_(fuel)/(F_(oxygen)+F_(fuel)), where F_(fuel) is equal to the molarflow rate of fuel and F_(oxygen) is equal to the molar flow rate ofoxygen.

The mol % oxygen is equal to F_(oxygen)/(F_(oxygen)+F_(fuel)), whereF_(oxygen) is equal to the molar flow rate of oxygen and F_(fuel) isequal to the molar flow rate of fuel. The molar flow rate of the oxygendepends on the proportion of oxygen to diluent in the oxidant mixture,and may be calculated as F_(oxygen)/(F_(oxygen)+F_(diluent)). As usedherein, the flow rate of the oxidant may be calculated asF_(oxidant)=(F_(oxygen)/F_(diluent)).

As the equivalence ratio (φ) 404 goes below 1 or above 1 the molefraction or concentration of oxygen and carbon dioxide in the exhaustgas changes. For example, as the equivalence ratio (φ) 404 goes below 1the mole fraction of oxygen rapidly increases from about 1 ppm (i.e., anoxygen mole fraction of about 1.0×10⁻⁶) at an equivalence ratio (φ) 404of about 1 to about 100 ppm (i.e., an oxygen mole fraction of about1×10⁻⁴) at an equivalence ratio (φ) 404 of about 0.999. Similarly, asthe equivalence ratio (φ) 404 goes above 1 the concentration of carbonmonoxide rapidly increase from about 1 ppm (i.e., carbon monoxide molefraction of about 1×10⁻⁶) at an equivalence ratio (φ) 404 of about0.9995 to greater than about 100 ppm (i.e., a carbon monoxide molefraction of about 1×10⁻⁴) at an equivalence ratio (φ) 404 of about1.001.

Based, at least in part, on the data obtained from the sensors, such assensors 206 (FIG. 2), or 312 (FIG. 3), the amount of oxidant 116 and/orthe amount of fuel 114 the combustors 110 can be adjusted to produce anexhaust stream 218 having a desired composition. For example, monitoringthe oxygen and/or carbon monoxide concentration in the exhaust gas inthe expander exhaust section 208 or the cooled exhaust stream 310 allowsthe adjustment of the amount of oxidant 116 and fuel 114 introduced thecombustors 110, either individual or as an ensemble, to be controlledsuch that combustion of the fuel 114 is carried out within apredetermined range of equivalence ratios (φ) 404 in the gas turbineengine 102. This can be used to produce an exhaust stream 218 having acombined concentration of oxygen and carbon monoxide of less than about3 mol %, less than about 2.5 mol %, less than about 2 mol %, less thanabout 1.5 mol %, less than about 1 mol %, or less than about 0.5 mol %.Furthermore, the exhaust stream 218 may have less than about 4,000 ppm,less than about 2,000 ppm, less than about 1,000 ppm, less than about500 ppm, less than about 250 ppm, or less than about 100 ppm combinedoxygen and carbon monoxide. In some embodiments, the fuel 114 andoxidant 116 are adjusted to form a slightly rich mixture to enhance theformation of CO at the expense of the O₂, favoring the water gas shiftreaction. In other embodiments, a slightly lean mixture is formed, toenhance the formation of O₂ at the expense of CO and unburnedhydrocarbons, favoring an oxidation reaction. However, as the exhaustwill contain a much higher content of water vapor, for example, at about10,000 ppm or higher, than any other reactive component, the water gasshift reaction may more favorable.

A desired or predetermined range for the equivalence ratio (φ) 404 inthe combustors 110 can be calculated or entered to carry out thecombustion of the fuel 114 to produce an mixed exhaust stream 418containing a desired amount of oxygen and/or carbon monoxide. Forexample, the equivalence ratio (φ) in the combustors 110 can bemaintained within a predetermined range of from about 0.85 to about 1.15to produce an exhaust stream 218 having a combined oxygen and carbonmonoxide concentration ranging from a low of about 0.5 mol %, about 0.8mol %, or about 1 mol %, to a high of about 1.5 mol %, about 1.8 mol %,about 2 mol %, or about 2.2 mol %. In another example, the equivalenceratio (φ) 404 in the combustors 110 can be maintained within a range ofabout 0.85 to about 1.15 to produce an exhaust stream 218 having acombined oxygen and carbon monoxide concentration of less than 2 mol %,less than about 1.9 mol %, less than about 1.7 mol %, less than about1.4 mol %, less than about 1.2 mol %, or less than about 1 mol %. Instill another example, the equivalence ratio (φ) 404 in the combustors110 can be maintained within a range of from about 0.96 to about 1.04 toproduce an exhaust stream 218 having a combined oxygen and carbonmonoxide concentration of less than about 4,000 ppm, less than about3,000 ppm, less than about 2,000 ppm, less than about 1,000 ppm, lessthan about 500 ppm, less than about 250 ppm, or less than about 100 ppm.

It will be noted that in embodiments in which the combustors 110 areindividually controlled, the combustors 110 do not have to be at thesame set-point, or even within the same range. In various embodiment,different or biased set-points may be used for each of the combustors110 to account for differences in construction, performance, oroperation. This may avoid a situation in which different operationalcharacteristics of different combustors 110 cause the exhaust stream 218to be contaminated with unacceptable levels of oxygen or carbonmonoxide. Also, it will be noted that a combination of combustionefficiency less that 100% and equivalence ratio differences among theindividual combustors 110 may result in both CO 408 and oxygen 406levels greater than those shown in FIGS. 4A and 4B at a given globalequivalence ratio 404.

Accordingly, in embodiments of the present techniques, two methods foroperating the gas turbine 102 are used. In a first method, the entireset of combustors 110 is operated as a single entity, for example,during startup and in response to global set-point adjustments, such asspeed or power changes. In a second method, the individual combustors110 may be separately biased, for example, to compensate for differencesin wear, manufacturing, and the like.

One method for operating the entire set of combustors 110 can includeinitially, i.e., on start-up, introducing the fuel 114 and oxygen in theoxidant 116 at an equivalence ratio (φ) 404 greater than 1. For example,the equivalence ratio (φ) 404 at startup may range from a low of about1.0001, about 1.0005, about 1.001, about 1.05, or about 1.1, to a highof about 1.1, about 1.2, about 1.3, about 1.4, or about 1.5. In anotherexample, the equivalence ratio (φ) 404 can range from about 1.0001 toabout 1.1, from about 1.0005 to about 1.01, from about 1.0007 to about1.005, or from about 1.01 to about 1.1. For global adjustments, theconcentration of oxygen and/or carbon monoxide in the exhaust stream 218can be determined or estimated via the sensors 206, 224, or 312. Theexpanded exhaust gas in the exhaust stream 218 may initially have a highconcentration of carbon monoxide (e.g., greater than about 1,000 ppm orgreater than about 10,000 ppm) and a low concentration of oxygen (e.g.,less than about 10 ppm or less than about 1 ppm).

Another method for operating the entire set of combustors 110 caninclude initially, i.e., on start-up, introducing the fuel 114 andoxygen in the oxidant 116 at an equivalence ratio (φ) 404 of lessthan 1. For example, the equivalence ratio (φ) 404 at startup may rangefrom a low of about 0.5, about 0.6, about 0.7, about 0.8, or about 0.9to a high of about 0.95, about 0.98, about 0.99, about 0.999. In anotherexample, the equivalence ratio (φ) 404 can range from about 0.9 to about0.999 from about 0.95 to about 0.99, from about 0.96 to about 0.99, orfrom about 0.97 to about 0.99. The expanded exhaust gas in the exhauststream 218 may initially have a high concentration of oxygen (e.g.,greater than about 1,000 ppm or greater than about 10,000 ppm) and a lowconcentration of carbon monoxide (e.g., less than about 10 ppm or evenless than about 1 ppm).

For example, when the concentration of oxygen in the exhaust gasincreases from less than about 1 ppm to greater than about 100 ppm,about 1,000 ppm, about 1 mol %, about 2 mol %, about 3 mol %, or about 4mol %, an operator, the control system 212, or both can be alerted thatan equivalence ratio (φ) 404 of less than 1 has been reached. In one ormore embodiments, the amount of oxygen via oxidant 116 and fuel 114 canbe maintained constant or substantially constant to provide a combustionprocess having an equivalence ratio (φ) 404 of slightly less than 1,e.g., about 0.99. The amount of oxygen via oxidant 116 can be decreasedand/or the amount of fuel 114 can be increased and then maintained at aconstant or substantially constant amount to provide a combustionprocess having an equivalence ratio (φ) 404 falling within apredetermined range. For example, when the concentration of oxygen inthe exhaust stream 418 increases from less than about 1 ppm to about1,000 ppm, about 0.5 mol %, about 2 mol %, or about 4 mol %, the amountof oxygen introduced via the oxidant 116 can be reduced by an amountranging from a low of about 0.01%, about 0.02%, about 0.03%, or about0.04% to a high of about 1%, about 2%, about 3%, or about 5% relative tothe amount of oxygen introduced via the oxidant 116 at the time theincrease in oxygen in the exhaust gas is initially detected. In anotherexample, when the concentration of oxygen in the exhaust stream 218increases from less than about 1 ppm to about 1,000 ppm or more theamount of oxygen introduced via the oxidant 116 can be reduced by about0.01% to about 2%, about 0.03% to about 1%, or about 0.05% to about 0.5%relative to the amount of oxygen introduced via the oxidant 116 at thetime the increase in oxygen in the exhaust gas is detected. In stillanother example, when the concentration of oxygen increases from lessthan about 1 ppm to about 1,000 ppm or more the amount of fuel 114 canbe increased by an amount ranging from a low of about 0.01%, about0.02%, about 0.03%, or about 0.04% to a high of about 1%, about 2%,about 3%, or about 5% relative to the amount of fuel 114 introduced atthe time the increase in oxygen in the exhaust gas is initiallydetected.

During operation of the gas turbine system 102, the equivalence ratio(φ) 404 can be monitored via the sensors 206, 224, or 312 on acontinuous basis, at periodic time intervals, at random or non-periodictime intervals, when one or more changes to the gas turbine system 102occur that could alter or change the equivalence ratio (φ) 404 of theexhaust stream 218, or any combination thereof. For example, changesthat could occur to the gas turbine system 102 that could alter orchange the equivalence ratio (φ) 404 can include a change in thecomposition of the fuel, a change in the composition of the oxidant, adegradation of the catalyst, for example, due to carbon formation, or acombination thereof. As such, the concentration of oxygen and/or carbonmonoxide, for example, can be monitored, and adjustments can be made tothe amount of oxidant 116 and/or fuel 114 to control the amounts ofoxygen and/or carbon monoxide in the exhaust stream 218, the product gas310, or both.

In at least one embodiment, reducing the equivalence ratio (φ) 404 canbe carried out in incremental steps, non-incremental steps, a continuousmanner, or any combination thereof. For example, the amount of oxidant116 and/or the fuel 114 can be adjusted such that the equivalence ratio(φ) 404 changes by a fixed or substantially fixed amount per adjustmentto the oxidant 116 and/or fuel 114, e.g., by about 0.001, by about 0.01,or by about 0.05. In another example, the amount of oxidant 116 and/orfuel 114 can be continuously altered such that the equivalence ratio (φ)404 continuously changes. Preferably the amount of oxidant 116 and/orfuel 114 is altered and combustion is carried out for a period of timesufficient to produce an exhaust gas of substantially consistentcomposition, at which time the amount of oxidant 116 and/or fuel 114 canbe adjusted to change the equivalence ratio (φ) 404 in an amount rangingfrom a low of about 0.00001, about 0.0001, or about 0.0005 to a high ofabout 0.001, about 0.01, or about 0.05. After the exhaust stream 218achieves a substantially consistent concentration of oxygen the oxidant116 and/or fuel 114 can again be adjusted such that the equivalenceratio (φ) 404 changes. The amount of oxygen and/or carbon monoxide inthe exhaust stream 418 can be monitored and the amount of oxidant 116and/or fuel 114 can be repeatedly adjusted until the exhaust stream 218has a combined concentration of oxygen and carbon monoxide, for example,of less than about 2 mol % or less than about 1.5 mol %, or less thanabout 1 mol %.

The combustors 110 can be operated on a continuous basis such that theexhaust stream 218 has a combined oxygen and carbon monoxideconcentration of less than 2 mol %, less than 1 mol %, less than 0.5 mol%, or less than about 0.1 mol %. In another example, the time duringwhich combustion is carried out within the combustors 110, the exhauststream 418 can have a combined oxygen and carbon monoxide concentrationof less than 2 mol % or less than about 1 mol % for about 50%, 55%, 60%,65%, 70%, 75%, 80%, 85%, 90%, or about 95% of the time during which thegas turbine engine-102 is operated. In other words, for a majority ofthe time that combustion is carried out within the combustors 110, theexhaust stream 418 can have a combined oxygen and carbon monoxideconcentration of less than about 2 mol %, less than about 1 mol %, lessthan about 0.5 mol %, or less than about 0.1 mol %.

Once the overall control of the gas turbine engine 102 is set, thebiasing needed for individual combustors 110 may be determined. Forexample, an oxidant flow adjusting device 202 for each individualcombustor 110 can be adjusted by the control system 212 to maintain themeasured value of the sensors 206, 224, or 312 at or near to a desiredset-point. Several calculated values may be determined from the measuredvalues of each sensor 206 or 312. These may include, for example, anaverage value that can be used to make similar adjustments to all of theoxidant flow adjusting devices 202 in the n combustors 110.

In addition, various difference values, for example, calculated based ondifferences of the measured values of two or more sensors 206, 224, or312, may be used to make biasing adjustments to the oxidant flowadjusting devices 202 on one or more of the combustors 110 to minimizedifferences between the measured values of the sensors 206, 224, or 312.The control system 212 may also adjust the oxidant system 116 directly,such by adjusting compressor inlet guide vanes (IGV) or a speed controlto change the oxidant flow rates, for example, to all of the combustors110 at once. Further, the control system 212 can make similaradjustments to the fuel 114 to all combustors 110, depending, forexample, on the speed selected for the gas turbine 102. As for theoxidant, the fuel supply to each of the combustors 110 may beindividually biased to control the equivalence ratio of the burn. Thisis discussed further with respect to FIG. 6.

FIG. 5 is a block diagram of a method 500 for adjusting fuel and oxidantlevels to the combustors 110 based on readings from an array of sensors206, 224, and 312. Like numbered items are as described in FIGS. 1, 2,and 3. It can be assumed that the gas turbine engine 102 has beenstarted before the method 500 begins, and that all of the combustors 110are using essentially the same mixture or a previous operation point.The method 500 begins at block 502, when a set-point for the oxidant 116is entered and oxidant is provided to the combustors 110. In asubstantially simultaneous manner, at block 504, a set-point is enteredfor the fuel 114, and fuel 114 is provided to the combustors 110. Atblock 506, the combustion process consumes the fuel 114 and oxidant 116provided.

At block 508, the exhaust gas is passed through one or more catalystbeds, for example, including oxidation catalysts, water gas shiftcatalysts, or both. At block 510, readings are obtained from the sensors206, 224, or 312. The readings may indicate the efficacy of the catalystprocesses, by determining the concentrations of H₂O, O₂, CO₂, H₂, andother gas components. These may be used to determine global adjustmentsto the combustors. Further, individual sensors 206 along the exhaustexpander ring 208 may be used to determine sums and differences ofconcentrations from individual combustors 110. The sums and differencesmay be combined to assist in identifying the combustors 110 that arecontributing to a high oxygen or high carbon monoxide condition in theexhaust. This may also be performed by a swirl chart, as describedabove. Adjustments to the fuel 114 and oxidant 116 for those combustors110 may be calculated and added to any global adjustments. Process flowthen returns to blocks 502 and 504 with the new set points, wherein themethod 500 repeats.

Control System

FIG. 6 is a block diagram of a plant control system 600 that may be usedto control the oxidant 116 and fuel 114 to the combustors 110 in a gasturbine engine 102. As previously mentioned, the control system 600 maybe a DCS, a PLC, a DDC, or any other appropriate control device.Further, any controllers, controlled devices, or monitored systems,including sensors, valves, actuators, and other controls, may be part ofa real-time distributed control network, such as a FIELDBUS system, inaccordance with IEC 61158. The plant control system 600 may host thecontrol system 212 used to adjust the fuel 114 and oxidant 116 to thecombustors 110, individually or as an ensemble.

The control system 600 may have a processor 602, which may be a singlecore processor, a multiple core processor, or a series of individualprocessors located in systems through the plant control system 600. Theprocessor 602 can communicate with other systems, including distributedprocessors, in the plant control system 600 over a bus 604.

The bus 604 may be an Ethernet bus, a FIELDBUS, or any number of otherbuses, including a proprietary bus from a control system vendor. Astorage system 606 may be coupled to the bus 604, and may include anycombination of non-transitory computer readable media, such as harddrives, optical drives, random access memory (RAM) drives, and memory,including RAM and read only memory (ROM). The storage system 606 maystore code used to provide operating systems 608 for the plant, as wellas code to implement turbine control systems 610, for example, bases onthe first or second methods discussed above.

A human-machine interface 612 may provide operator access to the plantcontrol system 600, for example, through displays 614, keyboards 616,and pointing devices 618 located at one or more control stations. Anetwork interface 620 may provide access to a network 622, such as alocal area network or wide area network for a corporation.

A plant interface 624 may provide measurement and control systems for afirst gas turbine system. For example, the plant interface 624 may reada number of sensors 626, such as the sensors 206, 224, and 312 describedwith respect to FIGS. 2 and 3. The plant interface 624 may also makeadjustments to a number of controls, including, for example, fuel flowcontrols 628 used adjust the fuel 114 to the combustors 110 on the gasturbine 102. Other controls include the oxidant flow controls 630, used,for example, to adjust the actuator 404 on an oxidant flow adjustingdevice 402, the actuator 706 on a oxidant flow adjusting valve 702, orboth, for each of the combustors 110 on the gas turbine 102. The plantinterface 624 may also control other plant systems 632, such asgenerators used to produce power from the mechanical energy provided bythe gas turbine 102. The additional plant systems 632 may also includethe compressor systems used to provide oxidant 116 to the gas turbine102.

The plant control system 600 is not limited to a single plant interface624. If more turbines are added, additional plant interfaces 634 may beadded to control those turbines. Further, the distribution offunctionality is not limited to that shown in FIG. 6. Differentarrangements could be used, for example, one plant interface systemcould operate several turbines, while another plant interface systemcould operate compressor systems, and yet another plant interface couldoperate generation systems.

TABLE 1 Simulation results for catalyst beds in HRSG A Stream Name inFIG. 7 1 4 5 6 7a 8b 9a Description Air to Air ex Fuel To Ex To Ex MACBAC Gas Expander Expander WGS WGS Temperature [C.] 10.6 400.0 54.51472.6 619.2 144.0 145.6 Pressure [kPa] 101.33 2496.65 4208.18 2157.68106.46 102.99 102.34 Molar Flow [kmol/sec] 12.17 12.17 1.31 25.11 29.7929.79 29.79 Mass Flow [kg/sec] 351.00 351.01 22.60 713.36 850.53 850.53850.53 Molecular Weight 28.85 28.85 17.24 28.41 28.55 28.55 28.55 MassDensity [kg/m3] 1.240 12.769 28.398 4.210 0.410 0.848 0.840 Heat Flow[kW] −38,633 104,695 −103,502 −525,545 −1,512,800 −1,985,133 −1,985,149Higher Heating Value 443.8 443.8 853006.3 6093.5 5616.3 5616.3 5566.0[kJ/kmol] Lower Heating Value 0.00 0.00 774305.31 613.11 609.41 609.41559.09 [kJ/kmol] (CO2) [kmol/sec] 0.03% 0.03% 2.00% 10.21% 10.39% 10.39%10.51% (H2O) [kmol/sec] 1.08% 1.08% 0.10% 13.31% 12.10% 12.10% 11.98%(Hydrogen) [ppmv] 0 0 0 (587)  (1082)   (1082)   (2308)   (CO) [ppmv] 00 0 (1619)   (1228)   (1228)   (2) (Nitrogen) [lbmole/hr] 77.24% 77.24%  3.00% 75.29% 76.30% 76.30% 76.30% (Oxygen) [ppmv] (207203)(207203) 0 (604)  (742)  (742)  (742)  (Argon) [kmol/sec] 0.93% 0.93%0.00%  0.90%  0.90%  0.90%  0.90% (Methane) [kmol/sec] 0.00% 0.00%92.91%   0.00%  0.00%  0.00%  0.00% (Ethane) [kmol/sec] 0.00% 0.00%2.00%  0.00%  0.00%  0.00%  0.00% (NO) [ppmv] 0 0 0 (143)  (0) (0) 0(NO2) [ppmv] 0 0 0 (0) 0 0 0 (H2S) [ppmv] 0 0 (1) (0) (0) (0) (0) (COS)[ppmv] 0 0 0 (0) (0) (0) (0) (SO2) [ppmv] 0 0 0 (0) (0) (0) (0) (SO3)[ppmv] 0 0 0 (0) (0) (0) (0) B Stream Name in FIG. 7 9b 10 11 12 13 1415 16 Description Ex To EGR Ex EGR Produced EGR to EGR to Purge Ex ExtrHRSG Blw Blw H2O RGT Comb Extr Cat Temperature [C.] 60.9 61.1 84.4 39.439.4 448.1 462.1 472.1 Pressure [kPa] 102.07 102.07 124.88 446.09 119.962276.04 2018.82 1998.14 Molar Flow [kmol/sec] 29.79 29.93 29.93 2.7327.87 23.16 11.56 11.55 Mass Flow [kg/sec] 850.53 853.13 853.13 49.13815.94 678.25 338.54 338.54 Molecular Weight 28.55 28.50 28.50 18.0229.28 29.28 29.28 29.30 Mass Density [kg/m3] 1.051 1.049 1.199 996.5261.354 11.043 9.616 9.396 Heat Flow [kW] −2,064,031 −2,095,760 −2,074,175−777,479 −1,617,366 −1,040,710 −513,319 −513,319 Higher Heating Value[kJ/kmol] 5566.0 5717.9 5717.9 41007.3 3101.6 3101.6 3086.7 2755.3 LowerHeating Value [kJ/kmol] 559.09 556.57 556.57 0.00 597.82 597.82 594.32261.18 (CO2) [kmol/sec] 10.51% 10.47% 10.47% 0.00% 11.25% 11.25% 11.25%  11.26%  (H2O) [kmol/sec] 11.98% 12.36% 12.36% 99.99%  5.86%5.86% 5.83% 5.97% (Hydrogen) [ppmv] (2308)   (2298)   (2298)   (0)(2468)   (2468)   (2453)   (1078)   (CO) [ppmv] (2) (3) (3) (0) (3) (3)(3) (2) (Nitrogen) [lbmole/hr] 76.30% 75.97% 75.97% 0.00% 81.60% 81.60%  81.62%  81.68%  (Oxygen) [ppmv] (742)  (738)  (738)  (0) (793) (793)  (785)  (97)  (Argon) [kmol/sec]  0.90%  0.90%  0.90% 0.00% 0.97%0.97% 0.97% 0.97% (Methane) [kmol/sec]  0.00%  0.00%  0.00% 0.00% 0.00%0.00% 0.00% 0.00% (Ethane) [kmol/sec]  0.00%  0.00%  0.00% 0.00% 0.00%0.00% 0.00% 0.00% (NO) [ppmv] 0 (0) (0) (0) (0) (0) (0) (0) (NO2) [ppmv]0 (0) (0) 0 0 0 0 0 (H2S) [ppmv] (0) (0) (0) (0) (0) (0) 0 0 (COS)[ppmv] (0) (0) (0) (0) (0) (0) 0 0 (SO2) [ppmv] (0) (0) (0) (0) (0) (0)0 0 (SO3) [ppmv] (0) (0) (0) (0) (0) (0) 0 0Simulated Results

FIG. 7 is a schematic of a simulated gas turbine system 700 thatillustrates the use of two catalyst beds in a heat-recovery steamgenerator (HRSG) to reduce the concentration of selected components inan exhaust stream. The reference numbers shown in circles in the drawingcorrespond to the stream names indicated in Table 1. The values in Table1 are the results for the conditions and concentrations generated in asimulation. The simulation was performed using the HYSYS ProcessModeling system from AspenTech.

For purposes of the simulation, air 702 was used as the oxidant,although any number of other oxidant blends could be used. The air 702was fed to a main air compressor 704, which caused a significantincrease in the temperature of the air 702. The main air compressor maycomprise one or more compressor stages with possible cooling between thestages. The compressed air was then injected into a combustor 712.

Fuel gas 714, which may be treated to remove impurities such as sulfurcompounds, was injected into the combustor 712. The fuel gas 714 can becompressed before the injection. Although the air 702 and fuel 714 wereinjected directly into the combustor 712 in the simulation, it can beunderstood that any number of other configurations are possible. Forexample, the air 702 and fuel 714 may be mixed prior to injection intothe combustor 712.

The exhaust gases from the combustor 712 were flowed into an expanderturbine 716, which is turned by expansion of the exhaust gases. From theexpander turbine 716, the exhaust gases were flowed to a heat-recoverysteam generator (HRSG) 718. In the HRSG 718, a water stream 720 isboiled to form a steam stream 722, cooling the exhaust gases.

An oxidation catalyst bed 724 may be located in the HRSG 718 at a pointwhere the temperature was still quite high, e.g., about 468° C. asindicated in Table 1. However, the simulation results in Table 1 do notinclude an oxidation catalyst.

The simulation did model a water gas shift (WSG) catalyst bed 726located at a cooler point in the HRSG 718, e.g., about 144° C. as shownin Table 1. The exhaust flowing through the WSG catalyst bed 726 showeda substantial change in CO, which dropped from about 1228 ppmv to about2 ppmv. Confirmation of the WSG reaction was provided by the hydrogenlevels, which increased from 1082 ppmv to 2308 ppmv, and the waterlevels, which dropped from 12.10% to 11.98%.

The product gas from the HRSG 718 was flowed to a compressor 730 forboosting the pressure to form a recycle stream. From the compressor 730,the recycle stream was flowed through a condensing HRSG 732. In thecondensing HRSG 732, a flow of water 734 is heated against the recyclestream, forming an outlet stream 736 that include hot water or steam.The outlet stream 736 may be used for other plant purposes, such asheating and utilities, or may be used as the water stream 720 to theHRSG 718. The cooling of the recycle stream caused water 738 to condensefrom the water vapor in the recycle stream. The water 738 can bediscarded or may be used as a water source for the process, or exportedas a product.

From the condensing HRSG 732, the recycle stream was fed to thecompression turbine 740, which is powered through mechanical energyprovided by the expander turbine 716 through a shaft 742. Although theshaft was shown as providing a direct connection in the simulation,other configurations could be used, including separate units, multipleshafts, and the like. Further, the shaft 742 may be extended to agenerator to provide electrical power. The compressed recycle stream wasthen reinjected into the combustor 712 to provide cooling.

In the simulation, a side stream was removed from the combustor 712 tofunction as a process purge. The side stream was flowed through aseparate oxidation catalyst bed 744, which caused a small decrease inthe CO content, e.g., 3 ppmv to 2 ppmv, a large reduction in thehydrogen level, e.g. from 2453 to 1079 ppm, a large reduction in theoxygen level, e.g. from 785 to 97 ppm, and a small increase in the waterconcentration, e.g. from 5.83 to 5.97%, in the simulation results. Thepurge 746 may then be used to generate additional steam or process heatin a waste heat recovery unit (e.g. a heat exchanger similar in functionas a HRSG), compressed, dehydrated in a glycol or similar dehydrationunit and/or separated into CO₂ rich and CO₂ lean streams. The purge 746or the CO₂ rich or CO₂ lean streams may subsequently be injected into asubterranean reservoir for the purpose of enhanced hydrocarbon recovery,CO₂ sequestration or both. It can be noted that a portion of the fuel714 can be diverted to the catalyst beds.

Embodiments

Embodiments of the invention may include any combinations of the methodsand systems shown in the following numbered paragraphs. This is not tobe considered a complete listing of all possible embodiments, as anynumber of variations can be envisioned from the description above.

1. A method for combusting a fuel in a gas turbine, including:

-   -   providing a fuel to a combustor on a gas turbine;    -   providing an oxidant to the combustor;    -   combusting the fuel and the oxidant in the combustor to produce        an exhaust gas; and    -   passing at least a portion of the exhaust gas through a        water-gas shifting catalyst to form a low CO content product        gas.

2. The method of paragraph 1, including providing a diluent to the gasturbine and gas turbine combustor; and mixing a first portion of thediluent with at least one of the fuel, the oxidant, and the exhaust gasto cool the combustor, exhaust gas, or both.

3. The method of paragraph 2, including:

-   -   extracting a second portion of diluent from the gas turbine or        gas turbine combustor; and    -   delivering the said second portion of diluent to an oxidation        catalyst unit configured to oxidize carbon monoxide, hydrogen        and unburned hydrocarbons to carbon dioxide and water vapor and        to produce a low oxygen content product gas.

4. The method of any of paragraphs 1-3, including:

-   -   compressing an oxidizing stream; and    -   providing a first portion of the oxidizing stream as the oxidant        to the combustor.

5. The method of any of paragraphs 1-4, including:

-   -   compressing a fuel stream; and    -   providing a first portion of the fuel stream as the fuel to the        combustor.

6. The method of any of paragraphs 2-5, including compressing thediluent prior to delivering the first portion of diluent to thecombustor and extracting a second portion of the diluent.

7. The method of paragraph 5, including providing a second portion ofthe fuel stream as a deoxidation fuel to an oxidation catalyst unit.

8. The method of paragraph 3, including providing a second portion ofthe oxidant as an oxidizer to the catalyst unit.

9. The method of paragraph 4 including providing essentially ambient airas the oxidizing stream.

10. The method of any of paragraphs 1-9, including:

-   -   measuring a parameter of the exhaust gas; and    -   adjusting a fuel flow rate, an oxidant flow rate, or both to        adjust the parameter to within a target set-point range.

11. The method of any of paragraphs 1-10, including:

-   -   measuring a parameter of the low CO content product gas; and    -   adjusting a fuel flow rate, an oxidant flow rate, or both to        adjust the parameter to within a target set-point range.

12. The method of any of paragraphs 1-11, including measuring aparameter including oxygen concentration, carbon monoxide concentration,hydrogen concentration, unburned hydrocarbon concentration, nitrogenoxides or any combinations thereof in the exhaust gas, the low COcontent product gas, or both.

13. The method of paragraph 12, including determining an equivalenceratio from the parameter.

14. The method of any of paragraphs 1-13, including adjusting the ratioof the fuel to the oxidant to form a substantially stoichiometricmixture.

15. The method of any of paragraphs 1-14, including adjusting the ratioof the fuel to the oxidant to obtain an exhaust gas including betweenabout 100 parts-per-million (ppm) of carbon monoxide (CO) and about 5000ppm of CO.

16. The method of any of paragraphs 1-15, including:

-   -   cooling the low CO content product gas to remove water;    -   compressing the low CO content product gas; and    -   recirculating the low CO content product gas to a combustor as a        diluent.

17. The method of any of paragraphs 1-16, including:

-   -   driving an expander turbine with the exhaust gas; and    -   generating mechanical power.

18. The method of any of paragraphs 1-17, including passing the exhaustgas through a second at least on oxidation catalyst bed configured tooxidize carbon monoxide, hydrogen and unburned hydrocarbons to carbondioxide and water vapor.

19. The method of any of paragraphs 1-18, including injecting at least aportion of at least one of the low CO content product gas and low oxygencontent product gas into a subterranean reservoir.

20. The method of paragraph 19, including compressing the portion of theat least one of the low CO content product gas and low oxygen contentproduct gas with a compressor prior to injecting the portion of the atleast one of the low CO content product gas and low oxygen contentproduct gas into the subterranean reservoir.

21. The method of any of paragraphs 3-20, including processing at leasta portion of at least one of the low CO content product gas and lowoxygen content product gas in a gas dehydration unit.

22. The method of any of paragraphs 3-21, including processing at leasta portion of at least one of the low CO content product gas and lowoxygen content product gas in a carbon dioxide separation unit toproduce a lean carbon dioxide stream and a rich carbon dioxide stream.

23. The method of paragraph 22, including injecting at least a portionof the lean carbon dioxide stream into a subterranean reservoir.

24. The method of paragraphs 22 or 23, including injecting at least aportion of the rich carbon dioxide stream into a subterranean reservoir.

25. The method of any of paragraphs 22-24, including providing at leasta portion of the rich carbon dioxide stream to a carbon sequestrationunit.

26. The method of paragraph 23, including compressing at least a portionof the lean carbon dioxide stream prior to injecting the lean carbondioxide stream into the subterranean reservoir.

27. The method of paragraph 24, further compressing the at least aportion of the rich carbon dioxide stream to at least one rich productcompressor prior to delivering the rich carbon dioxide stream to asubterranean reservoir for enhanced hydrocarbon recovery.

28. The method of paragraph 25, including compressing at least a portionof the rich carbon dioxide stream prior to providing the rich carbondioxide stream to a carbon sequestration unit.

29. The method of any of paragraphs 22-28, including processing at leasta portion of the lean carbon dioxide stream in a gas dehydration unit.

30. The method of any of paragraphs 22-29, including processing at leasta portion of the rich carbon dioxide stream in a gas dehydration unit.

31. The method of any of paragraphs 1-30, including cooling the exhaustgas in a heat recovery steam generator to produce steam.

32. The method of paragraph 31, including:

-   -   driving a steam turbine with the steam; and    -   generating mechanical power.

33. The method of paragraph 31, including heating process fluids withthe steam.

34. The method of any of paragraphs 1-33, including cooling the exhaustgas in a heat recovery unit; and

-   -   heating process fluids.

35. The method of any of paragraphs 3-34, including measuring aparameter including oxygen concentration, carbon monoxide concentration,hydrogen concentration, unburned hydrocarbon concentration, nitrogenoxides or any combinations thereof in the low oxygen content productgas.

36. The method of paragraph 35, including adjusting the flow rate of thedeoxidation fuel to cause the parameter to reach a target range.

37. The method of paragraph 35, including adjusting the flow rate of theoxidant to cause the parameter to reach a target range.

38. A gas turbine system, including:

-   -   an oxidant system;    -   a fuel system;    -   a control system;    -   a combustor adapted to receive and combust an oxidant from the        oxidant system and a fuel from the fuel system to produce an        exhaust gas; and    -   a catalyst unit including a water gas shifting (WGS) catalyst        configured to reduce the concentration of carbon monoxide in the        exhaust gas to form a low CO content product gas.

39. The gas turbine system of paragraph 38, including a sensor incommunication with the control system, wherein the sensor is adapted tomeasure at least one parameter of the exhaust gas, the low CO contentproduct gas, or both, and wherein the control system is configured toadjust the oxidant, the fuel, or both, based, at least in part, on theparameter measured by the sensor.

40. The gas turbine system of paragraphs 38 or 39, including arecirculation loop between an outlet of an expander section of a gasturbine engine and an inlet to a compressor section of the gas turbineengine.

41. The gas turbine system of paragraph 40 including a heat-recoverysteam generator (HRSG) configured to receive the exhaust gas from thegas turbine engine and to generate steam from the residual heat of theexhaust gas.

42. The gas turbine system of paragraph 40, wherein the HRSG includes atleast one catalyst bed.

43. The gas turbine system of paragraph 42, wherein the catalyst bedincludes the WGS catalyst, and wherein the catalyst bed is located in azone in the HRSG that reaches a temperature between about 100° C. andabout 450° C.

44. The gas turbine system of paragraph 42, wherein the catalyst bedincludes an oxidation catalyst, and wherein the catalyst bed is locatedin a zone in the HRSG that reaches a temperature between about 200° C.and 600° C.

45. The gas turbine system of any of paragraphs 38-44, including aplurality of combustors, wherein each combustor has an oxidant-flowadjustment device.

46. The gas turbine system of paragraph 45, wherein the oxidant-flowadjustment device includes a flow control valve.

47. The gas turbine system of paragraph 45, wherein the oxidant flow toeach of the plurality of combustors is individually adjusted.

48. The gas turbine system of any of paragraphs 40-47, including asecond heat recovery unit in the recirculation loop.

49. The gas turbine system of any of paragraphs 40-48, including asensor installed in the recirculation loop, wherein the sensor isconfigured to measure the constituents within the low CO content productgas.

50. The gas turbine system of any of paragraphs 40-49, including abooster blower in the recirculation loop, wherein the booster blower isdisposed downstream of the HRSG.

51. The gas turbine system of any of paragraphs 40-50, including a heatexchanger within the recirculation loop upstream of the compressorsection of the gas turbine engine cooling the product stream.

52. The gas turbine system of any of paragraphs 38-51, including a gasdehydration unit.

53. The gas turbine system of any of paragraphs 38-52, including acarbon dioxide separation unit configured to separate the product gasinto a lean carbon dioxide stream and a rich carbon dioxide stream.

54. A heat recovery unit, including:

-   -   a heat exchanger configured to remove heat energy from an        exhaust gas; and    -   a water gas shifting (WGS) catalyst bed configured to reduce a        concentration of a target gas in the exhaust gas.

55. The heat recovery unit of paragraph 54, wherein the WGS catalyst bedis located in a temperature region selected for operation of the WSGcatalyst.

56. The heat recovery unit of paragraphs 54 or 55s, including a secondcatalyst bed wherein the second catalyst bed includes an oxidationcatalyst located in a temperature region selected for operation of theoxidation catalyst.

57. The heat recovery unit of paragraph 54, 55, or 56, including a heatrecovery steam generator, including:

-   -   water circulation tubes configured to boil water into steam as        the exhaust gas is passed over the tubes; and    -   a surface coating over at least a portion of the tubes, wherein        the surface coating includes a refractory oxide support holding        metal catalytic sites.

58. The heat recovery unit of paragraph 57, wherein the metal catalyticsites are selected to perform a water gas shift reaction.

59. The heat recovery unit of paragraph 57, wherein the metal catalyticsites are selected to perform an oxidation reaction.

While the present techniques may be susceptible to various modificationsand alternative forms, the exemplary embodiments discussed above havebeen shown only by way of example. However, it should again beunderstood that the techniques is not intended to be limited to theparticular embodiments disclosed herein. Indeed, the present techniquesinclude all alternatives, modifications, and equivalents falling withinthe true spirit and scope of the appended claims.

What is claimed is:
 1. A method for combusting a fuel in a gas turbine,comprising: providing a fuel to a combustor on a gas turbine; providingan oxidant to the combustor; combusting the fuel and the oxidant in thecombustor to produce a combustor exhaust gas; expanding the combustorexhaust gas in a turbine expander to produce an exhaust gas thatcomprises water vapor, carbon dioxide, and between 1,000 and 5,000 ppmvof each carbon monoxide and hydrogen; passing at least a portion of theexhaust gas to a heat recovery unit that comprises a water-gas shiftingcatalyst; and converting a portion of the carbon monoxide and watervapor within the exhaust gas passed through the heat recovery unit intocarbon dioxide and hydrogen via a water gas shift reaction to form a lowCO content product gas.
 2. The method of claim 1, comprising providing adiluent to the gas turbine and gas turbine combustor; and mixing a firstportion of the diluent with at least one of the fuel, the oxidant, andthe exhaust gas to cool the combustor, exhaust gas, or both.
 3. Themethod of claim 2, comprising: extracting a second portion of diluentfrom the gas turbine or gas turbine combustor; and delivering the saidsecond portion of diluent to an oxidation catalyst unit configured tooxidize carbon monoxide, hydrogen and unburned hydrocarbons to carbondioxide and water vapor and to produce a low oxygen content product gas.4. The method of claim 1, comprising: compressing an oxidizing stream;and providing a first portion of the oxidizing stream as the oxidant tothe combustor.
 5. The method of claim 1, comprising: compressing a fuelstream; and providing a first portion of the fuel stream as the fuel tothe combustor.
 6. The method of claim 2, comprising compressing thediluent prior to delivering the first portion of diluent to thecombustor and extracting a second portion of the diluent.
 7. The methodof claim 5, comprising providing a second portion of the fuel stream asa deoxidation fuel to an oxidation catalyst unit.
 8. The method of claim3, comprising providing a second portion of the oxidant as an oxidizerto the catalyst unit.
 9. The method of claim 4 comprising providingessentially ambient air as the oxidizing stream.
 10. The method of claim1, comprising: measuring a parameter of the exhaust gas; and adjusting afuel flow rate, an oxidant flow rate, or both to adjust the parameter towithin a target set-point range.
 11. The method of claim 1, comprising:measuring a parameter of the low CO content product gas; and adjusting afuel flow rate, an oxidant flow rate, or both to adjust the parameter towithin a target set-point range.
 12. The method of claim 1, comprisingmeasuring a parameter comprising oxygen concentration, carbon monoxideconcentration, hydrogen concentration, unburned hydrocarbonconcentration, nitrogen oxides or any combinations thereof in theexhaust gas, the low CO content product gas, or both.
 13. The method ofclaim 12, comprising determining an equivalence ratio from theparameter.
 14. The method of claim 1, comprising adjusting the ratio ofthe fuel to the oxidant to form a substantially stoichiometric mixture.15. The method of claim 1, comprising adjusting the ratio of the fuel tothe oxidant to obtain an exhaust gas comprising between about 100parts-per-million (ppm) of carbon monoxide (CO) and about 5000 ppm ofCO.
 16. The method of claim 1, comprising: cooling the low CO contentproduct gas to remove water; compressing the low CO content product gas;recirculating the low CO content product gas to the combustor as adiluent; and providing the diluent to the combustor separately from theoxidant and the fuel.
 17. The method of claim 1, comprising: driving anexpander turbine with the exhaust gas; and generating mechanical powerfrom the turbine expander.
 18. The method of claim 1, comprising passingthe at least a portion of the exhaust gas through an oxidation catalystbed configured to oxidize carbon monoxide, hydrogen and unburnedhydrocarbons to carbon dioxide and water vapor.
 19. The method of claim1, comprising injecting at least a portion of at least one of the low COcontent product gas and low oxygen content product gas into asubterranean reservoir.
 20. The method of claim 19, comprisingcompressing the portion of the at least one of the low CO contentproduct gas and low oxygen content product gas with a compressor priorto injecting the portion of the at least one of the low CO contentproduct gas and low oxygen content product gas into the subterraneanreservoir.
 21. The method of claim 3, comprising processing at least aportion of at least one of the low CO content product gas and low oxygencontent product gas in a gas dehydration unit.
 22. The method of claim3, comprising processing at least a portion of at least one of the lowCO content product gas and low oxygen content product gas in a carbondioxide separation unit to produce a lean carbon dioxide stream and arich carbon dioxide stream.
 23. The method of claim 22, comprisinginjecting at least a portion of the lean carbon dioxide stream into asubterranean reservoir.
 24. The method of claim 22, comprising injectingat least a portion of the rich carbon dioxide stream into a subterraneanreservoir.
 25. The method of claim 22, comprising providing at least aportion of the rich carbon dioxide stream to a carbon sequestrationunit.
 26. The method of claim 23, comprising compressing at least aportion of the lean carbon dioxide stream prior to injecting the leancarbon dioxide stream into the subterranean reservoir.
 27. The method ofclaim 24, further compressing the at least a portion of the rich carbondioxide stream to at least one rich product compressor prior todelivering the rich carbon dioxide stream to a subterranean reservoirfor enhanced hydrocarbon recovery.
 28. The method of claim 25,comprising compressing at least a portion of the rich carbon dioxidestream prior to providing the rich carbon dioxide stream to a carbonsequestration unit.
 29. The method of claim 22, comprising processing atleast a portion of the lean carbon dioxide stream in a gas dehydrationunit.
 30. The method of claim 22, comprising processing at least aportion of the rich carbon dioxide stream in a gas dehydration unit. 31.The method of claim 1, comprising cooling the exhaust gas in a heatrecovery steam generator to produce steam.
 32. The method of claim 31,comprising: driving a steam turbine with the steam; and generatingmechanical power.
 33. The method of claim 31, comprising heating processfluids with the steam.
 34. The method of claim 1, comprising: coolingthe exhaust gas in a heat recovery unit; and heating process fluids. 35.The method of claim 3, comprising measuring a parameter comprisingoxygen concentration, carbon monoxide concentration, hydrogenconcentration, unburned hydrocarbon concentration, nitrogen oxides orany combinations thereof in the low oxygen content product gas.
 36. Themethod of claim 35, comprising adjusting the flow rate of thedeoxidation fuel to cause the parameter to reach a target range.
 37. Themethod of claim 35, comprising adjusting the flow rate of the oxidant tocause the parameter to reach a target range.
 38. A gas turbine system,comprising: an oxidant system; a fuel system; a control system; acombustor adapted to receive and combust an oxidant from the oxidantsystem and a fuel from the fuel system to produce a combustor exhaustgas; a turbine expander fluidly coupled to the combustor to receive thecombustor exhaust gas and produce an exhaust gas comprising water vapor,carbon dioxide, and between 1,000 and 5,000 ppmv of each carbon monoxideand hydrogen; and a heat recovery unit fluidly coupled to the expanderthat comprises a catalyst unit, the catalyst unit comprising a water gasshifting (WGS) catalyst configured to reduce the concentration of carbonmonoxide in the exhaust gas to form a low CO content product gas. 39.The gas turbine system of claim 38, comprising a sensor in communicationwith the control system, wherein the sensor is adapted to measure atleast one parameter of the exhaust gas, the low CO content product gas,or both, and wherein the control system is configured to adjust theoxidant, the fuel, or both, based, at least in part, on the parametermeasured by the sensor.
 40. The gas turbine system of claim 38,comprising a recirculation loop between an outlet of an expander sectionof a gas turbine engine and an inlet to a compressor section of the gasturbine engine.
 41. The gas turbine system of claim 40 comprising aheat-recovery steam generator (HRSG) configured to receive the exhaustgas from the gas turbine engine and to generate steam from the residualheat of the exhaust gas.
 42. The gas turbine system of claim 40,comprising a booster blower in the recirculation loop, wherein thebooster blower is disposed downstream of the HRSG.
 43. The gas turbinesystem of claim 40, comprising a heat exchanger within the recirculationloop upstream of the compressor section of the gas turbine enginecooling the product stream.
 44. A heat recovery unit, comprising: a heatexchanger configured to remove heat energy from an exhaust gas; and awater gas shifting (WGS) catalyst bed configured to reduce aconcentration of a target gas in the exhaust gas.
 45. The heat recoveryunit of claim 44, wherein the WGS catalyst bed is located in atemperature region selected for operation of the WSG catalyst.